Faribault Energy Park

Owned and developed by the Minnesota Municipal Power Agency, Faribault Energy Park far exceeds the usual expectations for a power plant. Located in southern Minnesota, the 252 MW combined cycle power plant facility was conceived as a model of environmental innovation and responsibility. The power plant was designed to meet the increasing regional energy needs while providing an aesthetically pleasing facility offering opportunities for both educational and recreational activities.

History of the Plant

The power plant was constructed in two phases. During the first phase, in the summer of 2005, the initial simple cycle gas turbine power plant was installed, producing 143 MW of power. During the second stage, in October 2007, the plant was upgraded into a combined cycle facility in order to produce an additional 100 MW. A combined cycle is the combination of a gas turbine and a steam power plant. One of the key components of the plant is a water recovery and filtration system that stores rainwater for the 35-acre site. Architectural features include three-story windows; exterior stone facing; office, meeting, and locker room facilities ; and a classroom from which visitors can view the control room and other parts of the plant. The landscaped acreage surrounding holding ponds features footpaths and educational displays.

Plant Operation

The GE 7FA gas turbine, the central component of the plant, uses natural gas and diesel fuel to power the plant. Diesel fuel is used on cold days in winter when the demand for natural gas is high. Compared to a typical train engine, which can generate up to 4500 hp, this gas can produce 230,000 hp to generate electricity for the surrounding region [119].

To operate the turbine, atmospheric air is drawn in and filtered through air ducts. During the winter, the incoming air is preheated by exhaust gases to the ideal operating temperature of air entering the compressor between 41°F and 45°F. During the summer, when the atmospheric air is hot and humid, the plant is only able to decrease the inlet temperature of the air by 10°F. The plant operates more efficiently during the winter months because the air can be heated to within the optimal temperature range, generating an additional 4-8 MW.

The generator, wound by the operation of the gas turbine, relays electricity to the grid at 18,000 volts (V). A transformer then steps up the voltage level to 150,000V. Once the voltage is increased, the electricity can be transported over long distances with minimal losses. The electrical power is transported to designated step-down transformers that reduce the voltage to levels appropriate for use in homes and businesses (in contrast to industrial applications).

The hot exhaust gas exits the gas turbine at 1155°F and is sent to the heat recovery steam generator (HRSG) where it heats circulation water flowing at 100,000 gpm through 15,000 tubes to create the steam that powers the steam turbine. The steam developed from the boiling water is separated into three pressure steam drums: the high pressure (HP) drum (approximately 1400 psi), the intermediate pressure (IP) drum (approximately 300 psi), and the low pressure (LP) drum (approximately 60 psi). These streams of differently pressured steam are then sent through the corresponding (HP, IP, and LP). Duct burners are used to raise the high-pressure steam from 1400 to 1900 psi. The front end processor (FEP) controls the duct burners to increase the steam turbine production from 84 MW to approximately 115 MW.

Between the first and second stages the steam turbine uses a reheating process to raise the temperature of the steam, generating more power and increasing efficiency. The steam exits the turbine at approximately 107°F and generates 84 MW. Approximately 2.4% of that power is used to operate the facility. On an average day in summer, the total power output is approximately 240 MW.

During the next step, the pressure in the steam turbine is lowered and the steam is condensed as it enters the condenser, which operates at 14.445 psia (-.255 psig). The steam then flows into the hot well, located directly below the condenser. A pump is used instead of a deaerator to send water to the low-pressure drum of the HRSG where it is heated and the oxygen is removed. The remaining hot well water is then pumped to the four-cell Baltimore Air cooling towers, seeping through tiny perforations in the pipes. As the water sprays through the pipes, giant fans at the top of the cooling towers supply an updraft of air, cooling the water as it falls.

The cooled water collects in the bed and is pumped along with makeup water back to the HRSG to generate steam.

The plant’s water treatment facility and four freshwater ponds located in the 35-acre park surrounding the plant supply the considerable amount of makeup water needed for the combined cycle process. The water entering the cycle must be processed before it enters the cycle, because contaminated water can damage tubing and other components. A water storage tank can store approximately 300,000 gallons of de-mineralized water that is used for controlling mono-nitrogen oxides (NOX) that result when fuel oil is fired. The chilled water storage capacity totals 2.5 million gallons. The facility can extract up to 1.9 million gallons of water per day. Waste water is discharged at a temperature no more than 5°F above the monthly average maximum (non-contact cooling water) into wetland areas created on-site.

Plant Emissions

One type of air emission control equipment is the dry low NOX (DLN) combustor, which is used when firing natural gas and steam/water injection when firing on fuel oil. The DLN combustor premixes air and fuel, reducing the peak flame temperature and the formation of thermal nitrogen oxide. There are fewer emissions of NOX from fuel-bound nitrogen (organic nitrogen contained in fuels) when firing natural gas than when firing crude oils. Conventional combustors inject fuel and air separately, creating hot spots inside the combustors that produce high levels of NOX. The DLN systems produce low levels of carbon monoxide and unburned hydrocarbons—the products of incomplete combustion.

By introducing a heat sink into the flame zone, the steam/water injections used when firing fuel oil lower the flame temperature and thus reduce the formation of NOX. Note, however, that care must be taken not to douse the flame with excessive injections.

Using a selective catalytic reduction system (SCR) is a way to reduce NOX emissions from the turbine exhaust. Installed inside the HRSG, the SCR, injects ammonia or urea into the flue gas that reacts with the NOX. The ammonia acts as a catalyst to produce pure nitrogen and water. The SCR has the capacity to removes up to 90% of the NOx in the combustion turbine exhaust stream.

Personnel in the Plant

The 18 onsite personnel include eight operators (four outside operators who conduct manual readings and check for leaks and flooding, and four inside operators who monitor the plant from the control room); four technicians, a plant operations manager, and a maintenance manager. Some of the staff also work in the chemistry laboratory, monitoring erosion levels associated with the boiler feed water.

Information current as of:July-2013

Click here to see a line drawing of the FEP plant.

Click here to see a line drawing of the FEP plant.

Want to learn more about how gas turbines like the GE 7FA work? Click here.